Processes for increasing hydrocarbon production

1. A process for increasing hydrocarbon production using an electrical submersible pump comprising:

configuring an electrical submersible pump comprising a gas separator to induce a gas lift effect in a well wherein the well comprises a central tubing within a casing such that an annulus is formed between the central tubing and the casing; and

producing hydrocarbons from the well with the electrical submersible pump such that reservoir fluid is produced up the central tubing and a mixture comprising reservoir gas and reservoir fluid is produced up the annulus,

wherein the configuring step comprises suspending the electrical submersible pump from the central tubing such that velocity of a gas separated by the gas separator is above a critical velocity of reservoir fluid from the well.

2. The process of claim 1 wherein the gas lift effect is induced in the absence of injecting gas into the well from the surface.

3. The process of claim 1 wherein the configuring step comprises suspending the electrical submersible pump from the central tubing such that the central tubing within the casing comprises a casing clearance which is less than about 30% of the casing diameter uphole from the electrical submersible pump.

4. The process of claim 3 , wherein the hydrocarbons produced from the well wherein the casing clearance is less than about 30% of the casing diameter uphole from the electrical submersible pump are at least 5% up to 20% than a process without said casing clearance of less than about 30% of the casing diameter uphole from the electrical submersible pump.

5. The process of claim 3 , wherein the hydrocarbons produced from the well wherein the casing clearance is less than about 30% of the casing diameter uphole from the electrical submersible pump are about the same or more than a process without said casing clearance of less than about 30% of the casing diameter uphole from the electrical submersible pump and wherein the process uses at least 6% up to 29% horsepower over the time of a given electrical submersible pump (ESP) run.

6. The process of claim 1 wherein the configuring step comprises suspending the electrical submersible pump from the central tubing such that the central tubing within the casing comprises a casing clearance which is less than about 20% of the casing diameter uphole from the electrical submersible pump.

7. The process of claim 1 wherein the configuring step comprises suspending the electrical submersible pump from the central tubing and employing one or more additional tubing strings into the annulus that extend at least from a surface into the well and terminate uphole from the electrical submersible pump wherein the sum of diameters of the central tubing and the one or more additional tubing strings is less than about 30% of the casing diameter uphole from the electrical submersible pump.

8. The process of claim 7 wherein the mixture comprising reservoir gas and reservoir fluid is produced up the annulus wherein at least a portion of the mixture comprising reservoir gas and reservoir fluid produced up the annulus passes through the one or more additional tubing strings.

9. The process of claim 7 wherein the one or more additional tubing strings comprise a smaller diameter than the central tubing.

10. The process of claim 1 wherein the configuring step comprises suspending the electrical submersible pump from the central tubing and employing one or more additional tubing strings into the annulus that extend at least from a surface into the well and terminate uphole from the electrical submersible pump wherein the sum of diameters of the central tubing and the one or more additional tubing strings is less than about 30% of the casing diameter uphole from the electrical submersible pump.

11. The process of claim 1 wherein the separation efficiency of the gas separator is from about 60 to about 100%.

12. The process of claim 1 wherein the electrical submersible pump has an intake pressure below the bubble point of the reservoir.

13. The process of claim 1 , wherein critical velocity of reservoir fluid varies depending upon cross-sectional flow area, or wellhead pressure.

14. A system for increasing hydrocarbon production using an electrical submersible pump comprising:

a well comprising a central tubing within a casing wherein the central tubing comprises a fluid exit opening near a surface of the well and a fluid entrance opening downhole;

an electrical submersible pump suspended from the fluid entrance opening of the central tubing;

wherein the electrical submersible pump comprises a pump operably connected to the fluid entrance opening of the central tubing, a gas separator operably connected to the pump, and a motor operably connected to the gas separator;

wherein the system is configured to produce reservoir fluid up the central tubing and to produce a mixture comprising reservoir fluid and reservoir gas up an annulus between the central tubing and the casing;

wherein the system is configured to induce a gas lift effect in the absence of injecting gas into the well from the surface

by suspending the electrical submersible pump from the central tubing such that velocity of a gas separated by the gas separator is above a critical velocity of reservoir fluid from the well.

15. The system of claim 14 which further comprises: one or more tubing strings uphole from the electrical submersible pump wherein the one or more tubing strings are in the annulus between the casing and the central tubing wherein the one or more tubing strings are configured to produce a mixture comprising reservoir fluid and reservoir gas up the annulus through the one or more tubing strings.

16. The system of claim 15 , wherein at least one tubing string is smaller in cross-section than the central tubing.

17. The system of claim 14 , wherein the central tubing within the casing comprises a casing clearance which is less than about 30% of the casing diameter uphole from the electrical submersible pump.

18. The system of claim 14 , wherein the central tubing within the casing comprises a casing clearance which is less than about 30% of the casing diameter uphole from the electrical submersible pump.

19. The system of claim 14 , wherein critical velocity of reservoir fluid varies depending upon cross-sectional flow area, or wellhead pressure.